A. Field of the Invention
This invention relates to drilling apparatus and methods, and more particularly to such drilling apparatus and methods used for drilling or coring deep holes in subsurface earth formations, such as drilling holes in rock in connection with the fossil fuel industry.
B. Background Art
Drill bits incorporating fixed cutting surfaces (drag bits) are widely used in the fossil fuel industries for drilling soft to medium strength rock. The bit is rotated and pushed against the rock by the drill stem, causing the cutting surfaces (cutters) on the bit to dig into the rock and scrape rock fragments (cuttings) from the work face. A fluid (water, air, foam or drilling "mud") is pumped through the drill stem, and then out and around the drill bit to flush cuttings away from the work face so that the cutters can continually contact fresh rock. The fluid also acts to cool the cutters and bit body, removing heat generated by friction from scraping the rock and heat emitted from the rock formation.
Cutters used for drag bits are constructed of extremely hard materials such as tungsten carbide, natural diamonds and man-made polycrystalline diamond (PDC & TSD). These cutters are wear resistant but expensive to manufacture. Drag bits mounting these cutters can advance rapidly through rocks with low to medium strength and abrasiveness and survive adequately to achieve economic life. However, many rock formations frequently encountered are strong and abrasive and cause rapid wear or breakage of the best drag bit cutters.
As rock strength increases, higher axial loads are required on the drill bit to force the cutters to penetrate into the work face. This increases the rate of frictional heating and accelerates heat induced fracture and degradation of the cutter edges. Abrasive rock particles also accelerate frictional heating and abrasive wear on the cutters. The wear flats grow, requiring even higher axial forces to push the cutter into the rock. The result is a "snowball" effect of increasing frictional heating and wear. Soon the wear flats become so large that the maximum axial force available is insufficient to force the cutters far enough into the rock to enable an economic advance rate for the drag bit.
A second cause of cutter failure is rapid load variations on the cutter edges due to the elastic failure mode of some strong or brittle rock types. Many softer rocks fail in a plastic mode with relatively constant forces on the cutter edges, which scrape away uniform furrows of rock particles similar to a plow shearing through moist topsoil. Brittle rocks fail in irregular fragments, causing rapid build-up and release of forces on the cutter edges. If the cut depth is too deep, the force surges can be large enough to fracture the cutters. The rapid intermittent cyclic loading also causes fatigue of the cutter edges and can excite vibration of the drill bit or initiate eccentric bit rotation, further accelerating cutter wear and failure.
A third cause of cutter failure is inconsistent rock hardness. This often occurs in thinly bedded sedimentary rocks or rocks interspersed with nodules or crystals of harder material. The depth of cut that will cause forces sufficiently high to break a cutter is much less for hard brittle rock than for soft rock. The axial force on the drill bit causes the cutters to bite further into soft rock than into hard. If a hard spot is suddenly encountered, the cut depth at that instant may be too great, causing cutters to fracture.
Prior attempts to reduce cutter wear and failure have included:
a. improving cutter materials to increase wear resistance;
b. modifying individual cutter shape and geometry to reduce forces on the cutter;
c. modifying bit body geometry to improve cutter chip flushing and cooling;
d. adding extra cutters near the bit perimeters (gauge) where wear is most severe;
e. improving bit body materials to strengthen cutter attachment;
f. modifying bit body design to minimize the possibility of eccentric rotation; and
g. mounting poses (studs) behind the cutters to reduce impact loading.
These changes have greatly improved drag bits, allowing them to be used economically in rocks with medium strength and abrasiveness instead of only in soft rocks as was the case previously. However, they still cannot economically drill hard abrasive rock. To the best knowledge of the applicant, at present drag bits account for less than one third of total bit usage.
Accordingly these rock formations are typically drilled with roller cone bits that use rotating conical wheels holding teeth that crush and gouge the rock. Roller cone bits are more durable in hard rock but advance more slowly than drag bits, increasing the time, and hence the time dependent portion of costs, to complete the drilling project.
It has also been known in the drilling industry to use ultra high pressure liquid jets (as high as 35,000 PSI or higher, sometimes in conjunction with small abrasive particles entrained therein) in conjunction with roller cone bits to assist the drilling process. The discharge nozzles are located adjacent to the operating surface of the bit to discharge the liquid jets into the end wall surface of the drill hole and weaken the rock material. To maximize the effect of the ultra high pressure jets, it is desirable that these be placed as closely as possible to the rock formations on which the liquid jet impinges. However, with the jet discharge orifices being placed more closely to the rock surface that is being cut, there is a greater chance of damage to the nozzles. This could occur, for example, by the jet nozzle contacting a protrusion or irregularity in the rock, or by a fragment of rock. Another problem is "splash back", in that material (e.g. rock fragments) may be caused to rebound from the end wall surface and strike the jet nozzle assembly and damage the same.
A search of the patent literature has disclosed patents, these being the following:
U.S. Pat. No. 5,004,056 (Goikhman et al) discloses a percussion-rotary drilling tool where there are drilling elements 5 and 6, mounted in a casing 8 at the drilling location. The outer rock crushing elements 9 are provided with spring loaded locating elements 16, formed with a retaining element 17 having a spring 18. Patentability seems to be predicated primarily on this feature. As the rock crushing elements 5 and 6 wear out and thus decrease in height, the reaction of the bottom surface of the borehole on the support elements 22 which in turn is mounted to the casing 2 causes the casing 2 to move upwards. It is stated in column 6, line 49 that during upward movement of the casing 2, the rock crushing elements are displaced toward the periphery of the tools which ensures a constant diameter of the tool, and in effect a constant diameter of the borehole 15.
There is a group of four related patents, naming John Fuller as the inventor or a co-inventor, these being the following: U.S. Pat. No. 4,718,505; U.S. Pat. No. 4,823,892; U.S. Pat. Nos. 4,889,017 and 4,991,670. Insofar as these patents relevant to the concepts of the present invention, all of these have essentially the same basic disclosure. For convenience, reference will be made to the latest patent to issue. This discusses the problem of deep drilling where the drill passes through a comparatively soft formation and strikes a significantly harder formation or possibly hits some hard occlusions within the soft formation. The cutting elements in the drill bit may be subjected to very rapid wear. One prior art solution was to provide adjacent the rearward side of the cutting element a body of material impregnated with natural diamond. In this instance where the cutting element experiences rapid wear or fracture, the diamond impregnated support on which the element is mounted takes over the abrading action of the cutting element and permits continued use of the drill bit. It is stated that one disadvantage of this is that the diamond impregnated support generates a great deal of heat and the resultant high temperature tends to cause rapid deterioration. This patent shows an arrangement where there are a plurality of cutting elements 15 and spaced a short distance rearwardly of these cutting elements 15 are "abrading elements 16". For example, as shown in FIG. 3, each cutting element 15 has front thin hard facing layer 17 of polycrystalline diamond bonded to a thickening backing layer. Each abrasion element 16 comprises a cylindrical stud and it is coated with particles 21 of natural or synthetic diamond or other super hard material.
U.S. Pat. No. 4,790,394 (Dickinson et al) relates generally to the use of high velocity cutting jets to bore a hole. There are various arrangements, and one is to provide a whirling mass of pressurized fluid in a chamber and discharge it through a nozzle in the form of a high velocity cutting jet having a shape of a thin conical shell.
U.S. Pat. No. 4,558,753 (Barr) relates to cutting elements for a drill, and these cutting elements have different back rake angles. One function of this invention is to have two sets of cutting members, one set having its cutting faces closer to the end operating face of the bit body than the cutting faces of the other set. The back rake angles of the cutting faces of the innermost set are more negative than the rake angles of the outer cutting faces. As the bit operates, the cutters with the less negative rake angles will contain and cut the more soft formation, this being accomplished rather rapidly. However, at such time as it enters into a hard rock formation, the outermost set of cutters (i.e. the more forward set) will quickly chip or break away so that the remaining cutters having a more negative rake angles can continue the drilling.
U.S. Pat. No. 4,543,427 (Wang et al) discloses a drilling apparatus which provides an abrasive containing fluid jet. There are mechanical cutting means which break off the material between the grooves which are formed by the high pressure jets, so as to form a completed borehole.
U.S. Pat. No. 4,397,361 (Langford, Jr.) shows a rotary drill bit where there is a number of protective protruding elements that extend beyond the cutters. As the bit is moving down the borehole or otherwise being handled, these protectors, prevent damage to the cutting elements. During operation, these protective members are worn away, leaving the cutting elements to engage the ground surface and function during the boring operation.
U.S. Pat. No. 4,262,757 and U.S. Pat. No. 4,391,339 (both of which issued to Johnson, Jr. and three other inventors) are two related patents (one being a continuation of the other) having identical drawings and descriptions. These relate to a drill bit for deep hole drilling combining mechanical cutting and plurality of "cavitating liquid jet nozzles" to assist in the drilling action.
U.S. Pat. No. 4,351,401 (Fielder) discloses a concept for earth boring drill bits. In the bit section, there is a coating of a hard wear resistant material and cutters are mounted in the sockets in this material. Penetration of the cutters is controlled by diamonds that are embedded in the hard material adjacent to the gauge of the bit and extending around the gauge of the bit. These engage the surface of the material being cut so as to control the depth of the cut.
U.S. Pat. No. 4,253,533 (Baker, III.) shows a drill bit where there are a number of diamond insert cutter blanks at the face of the bit. There are two wear pads positioned on diametrically opposed portions of the operating face of the drill bit. These wear pads serve to channel the flow of drilling mud emanating from fluid passages formed in the face of the drill bit.
U.S. Pat. No. 4,174,759 (Arbuckle) shows a rotary drill bit where there are mechanical rock breaking wheels. Also, a high pressure fluid jet cuts grooves in the bore bottom.
U.S. Pat. No. 4,073,354 (Rowley et al) shows an earth boring drill bit. The subject matter of this patent appears to be closely related to a later issued patent discussed above (U.S. Pat. No. 4,351,401) which is assigned to the same assignee (Christensen, Inc.), and having one common inventor. This patent shows a particular type of cutting element.
U.S. Pat. No. 3,838,742 (Juvkam-Wold) discloses a drill in which high pressure abrasive jets cut a series of concentric grooves in the bore bottom. There are wedge-like elements that break up the material between the grooves.
U.S. Pat. No. 3,542,142 (Hasiba) shows a drill bit where there are some high velocity fluid jets discharged from the working face of the drill bit to form concentric circular grooves. Loading elements ride in the grooves to break up the material.
U.S. Pat. No. 3,419,220 (Goodwin et al) shows an abrasive jet nozzle. The end of the nozzle has a tapered configuration, and this nozzle is used to discharge a fluid abrasive slurry. The inner material which comes in contact with the slurry is described as being more abrasive resistant.
U.S. Pat. No. 3,235,018 (Troeppl) shows what is called an "Earth Auger Construction". This shows a particular arrangement of teeth spaced radially outwardly from one another. The two diametrically opposed sets of teeth appear to travel in different grooves, and one set appears to be spaced somewhat lower than the other.
U.S. Pat. No. 3,111,179 (Albers) shows a nozzle element for an earth boring jet drill. The nozzle element is made of a shell 21 that is formed in a casing 22. The shell is of abrasive resistant material such as tungsten carbide and the casing is a less expensive material that lends support and strength to the nozzle.